High conformance oil recovery process

ABSTRACT

The conformance of an enhanced oil recovery process, including waterflood, surfactant or other chemicalized water flood process, in a formation containing at least two strata or zones of varying permeability, the permeability of one zone being at least 50 percent greater than the permeability of the other zone, is improved by flooding until the higher permeability zone has been depleted, after which an aqueous fluid is injected into the high permeability zone, said fluid having relatively low viscosity at the time of injection and containing a blend of surface active agents which promote the formation of a coarse viscous emulsion in the flow channels of the formation which reduces the permeability of the high permeability zone. After the permeability of the first zone has been reduced substantially, flooding may then be accomplished in the second zone which was originally not invaded by the injected oil recovery fluid. The surface active agents are individually tailored and the ratio of dissimilar surfactants balanced to exhibit optimum viscous emulsion formation properties. The optimum emulsifying surfactant comprises a mixture of an organic sulfonate such as petroleum sulfonate and a solubilizing co-surfactant such as an alkyl or alkylarylpolyalkoxy alkylene sulfonate and/or a low molecular weight alcohol.

FIELD OF THE INVENTION

This invention concerns a process for use in subterranean formationscontaining two or more zones which differ from one another inpermeability to such a degree that water flooding or other enhanced oilrecovery processes cannot effectively deplete both zones, resulting inpoor vertical conformance. More specifically, the process involvesinjecting a fluid into the more permeable zone, after it has beendepleted by water flooding or other supplemental oil recovery process,which fluid has relatively low viscosity at the time of injection butforms a high viscosity, coarse emulsion with the residual hydrocarbon inthe depleted zone to reduce the permeability of that zone tosubsequently injected fluids.

BACKGROUND OF THE INVENTION

It is well recognized by persons skilled in the art of petroleumrecovery that only a small fraction of the petroleum originally presentin a formation can be recovered by primary production, e.g., by allowingthe oil to flow to the surface of the earth as a consequence ofnaturally occuring energy forces, or by so called secondary recoveryprocesses which comprise injecting water into the formation by one ormore wells to displace petroleum laterally through the formation towardone or more spaced apart production wells and then to the surface of theearth. Although water flooding is an inexpensive supplemental oilrecovery process, water does not displace oil effectively even in thoseportions of the formation through which it passes, because water and oilare immiscible and the interfacial tension between water and oil isquite high. This too has been recognized by persons skilled in the artof oil recovery and many surface active agents or surfactants have beenproposed for addition to the flood water, which materials reduce theinterfacial tension between the injected aqueous fluid and the formationpetroleum thereby increasing the microscopic displacement efficiency ofthe injected aqueous fluid. Surfactants which have been disclosed in theprior art for such purposes include alkyl sulfonates, alkylarylsulfonates, petroleum sulfonates, alkyl or alkylarylpolyalkoxy sulfates,alkyl- or alkylarylpolyalkoxyalkylene sulfonates, nonionic surfactantssuch as polyethoxylated aliphatic alcohols or alkanols, andpolyethoxylated alkylphenols, and numerous mixtures thereof.

Even if the surface tension between the injected aqueous fluid and thepetroleum present in the subterranean reservoir can be reduced byincorporating surface active agents into the injected fluid, the totaloil recovery efficiency of the process is frequently poor because manysubterranean petroleum-containing reservoirs are comprised of aplurality of layers of widely differing permeabilities. When any oilrecovery fluid is injected into such a heterogeneous reservoir, thefluid passes primarily through the most permeable zones and little ornone of the fluid passes through the lower permeability zones. If theratio of permeabilities of the zones is as high as 2:1, essentially allof the injected fluid passes through the more permeable zone to thetotal exclusion of the less permeable zone. Furthermore, the situationdescribed immediately above causing poor vertical conformance of theinjected fluid in a heterogeneous reservoir is aggravated by applicationof the supplemental oil recovery process itself. If water or any otheroil displacing fluid is injected into a heterogeneous multi-layeredpetroleum reservoir, the fluid passes principally through the mostpermeable zone and displaces petroleum therefrom, and as a consequencefurther increases the permeability of that zone. Accordingly, thedifference between the permeability of the most permeable zone and theless permeable zone or zones is increased as a consequence of applying afluid displacement oil recovery process thereto, including waterflooding, surfactant flooding, etc.

The above described problem of poor vertical conformance in waterflooding operations has also been recognized by persons skilled in theart, and numerous processes have been described in the prior art fortreating the formation to correct the problems encountered wheninjecting an oil-displacing fluid into a formation having two or morezones of significantly different permeabilities. Many of the theseprocesses involve the use of solutions of hydrophilic polymers includingpartially hydrolyzed polyacrylamide, copolymers of acrylamide andacrylic acid or water soluble acrylates, polysaccharides, etc.Unfortunately, the fluids employing these hydrophilic polymers aresubstantially more viscous than water at the time of injection, and soinjection into the zones is difficult and there is little assurance thatthey will invade the same zones as would water or another aqueous fluidhaving about the same viscosity as water. Accordingly, the effectivenessof these prior art processes has been restricted to reducing thepermeability of only the most permeable flow channels in a zone, andonly affects the permeability distribution of the near wellbore zone ofthe formation, e.g. that portion of the most permeable zone in aformation immediately adjacent to the injection well, because of thedifficulty of injecting viscous fluids through large portions of theformation.

In view of the foregoing discussion of the problems associated with poorvertical conformance in heterogeneous formations, it can be appreciatedthat there is a substantial need for a method of treating suchformations to achieve indepth reduction of the permeability of the veryhigh permeability zones to force subsequently injected oil displacingfluids to pass into those zones which were originally of lowerpermeability, and so were not invaded by the first injected fluids.

DESCRIPTION OF THE PRIOR ART

Numerous references suggest formulating viscous emulsions on thesurface, and injecting the emulsion into a subterranean formation forthe purpose of decreasing the permeability of a zone which wasoriginally more permeable than other zones. These include U.S. Pat. Nos.3,149,669; Re. 27,198 (original U.S. Pat. No. 3,443,636); U.S. Pat. No.3,502,146 (1970); and U.S. Pat. No. 3,866,680 (1975). U.S. Pat. Nos.3,827,497; and 3,890,239 relate to the use of interfacial tensionreducing mixtures of organic sulfonate and ethoxy sulfonate surfactantsin an oil displacing fluid.

SUMMARY OF THE INVENTION

We have discovered a process applicable to subterranean,petroleum-containing formations containing two or more zones, at leastone of which has a permeability at least 50 percent greater than theother zone, which will permit application of enhanced oil recoveryprocesses such as water flooding or surfactant flooding in both zones.The process involves first injecting water or other aqueous displacingfluid into the formation to pass through the more permeable zone,displacing petroleum therefrom, until the ratio of injected fluid toformation petroleum of fluids being recovered from the formation reachesa predetermined or economically unsuitable level. This further increasesthe ratio of the permeability of the most permeable zone to thepermeability of the lesser permeable zone or zones. Thereafter anaqueous emulsifying fluid is injected into the formation, which fluidflows substantially exclusively into and through the most permeable,previously water flooded zone. Injection into the zone may be by meansof the well utilized as the injection well initially, or by means of theproduction well, or by both wells simultaneously or sequentially. Thefluid has a viscosity not substantially greater than the viscosity ofwater, and contains a surfactant combination which readily emulsifiesthe residual oil present in the previously water flooded zone. Thesurfactant mixture present in the injected treating fluid must be onewhich forms an emulsion with the residual formation petroleum in thezone being treated at a salinity about equal to the salinity of theaqueous fluid present in the previously flooded, high permeability zone,and should also be relatively stable with changes in salinity sincethere are normally variations in water salinity from one point in asubterranean formation to another. The emulsion formed should also bestable for a long period of time at the temperature of the formation, inorder to maintain the desired reduction of permeability within thetreated zone. The surfactant employed in the process of our inventioncomprises at least two components: (1) an organic sulfonate such as awater soluble salt, preferably a sodium, potassium or ammonium salt ofan alkyl or alkylaryl sulfonate having from 6 to 25 and preferably from8 to 18 carbon atoms in the alkyl chain, which may be linear orbranched, or a water soluble salt, preferably a sodium, potassium orammonium salt of petroleum sulfonate having a median equivalent weightfrom 325 to 475, and (2) a solubilizing co-surfactant, preferably awater soluble salt of an alkyl or alkylarylpolyalkoxyalkylene sulfonatehaving the following formula:

    RO(R'O).sub.n R"SO.sub.3 M

wherein R is an alkyl, linear or branched and having from 8 to 22 andpreferably from 10 to 18 carbon atoms, or an alkylaryl such as benzene,toluene or xylene having attached thereto an alkyl, linear or branched,containing from 8 to 15 and preferably from 9 to 13 carbon atoms in thealkyl, R' is ethylene or a mixture of ethylene and higher alkylene suchas propylene with relatively more ethylene than higher alkylene,preferably at least 65% ethylene, R" is ethylene, propylene, hydroxypropylene or butylene, n is a number from 2 to 20 and preferably from 4to 12, and M is a monovalent cation, preferably sodium, potassium orammonium.

The equivalent weight of the organic sulfonate, the balance between Rand x in the above formula and the weight ratio of solubilizingco-surfactant are all chosen based on experimentation using petroleumand brine from the formation into which the fluid will be injected, onthe basis of exhibiting the best combination of the following:

(1) Optimum emulsifying property;

(2) Maximum emulsion viscosity;

(3) Emulsion brine tolerance;

(4) Maximum stability of emulsion at formation temperature and salinity;

(5) Tolerance for changes in aqueous fluid salinity within the range ofvariations expected in the formation and which may be caused bysubsequently injecting fluids having greater or less salinity than thesalinity of the aqueous phase of the emulsion.

A low molecular weight alcohol, e.g. a C₂ to C₇ alkanol or analkyl-substituted phenol having from 1 to 5 carbon atoms in the alkylchain, may be required or used advantageously for use in the emulsifyingfluid, to enhance the emulsification-forming properties or to enhancethe stability of the emulsion.

In a slightly different preferred embodiment of the process of ourinvention, a small amount of hydrocarbon is added to the emulsifyingliquid to form an emulsion, micellar dispersion or microemulsion. Thehydrocarbon may be crude oil, as well as kerosene, naphtha, gasoline orother commercially available mixtures, as well as C₆ to C₂₄hydrocarbons, preferably saturated hydrocarbons. The amount ofhydrocarbon which is incorporated in the emulsion is determinedexperimentally from the aqueous emulsifying fluid by preparing samplescontaining various concentrations of hydrocarbon over the range of 0.05to about 15.0 and preferably 0.5 to 5.0 percent by volume, anddetermining the viscosity of each sample. The maximum amount ofhydrocarbon which can be incorporated in the fluid without causing theviscosity of the fluid to exceed the viscosity of water or brine atformation conditions by more than 500% and preferably by no more than200%, is selected. By incorporating this small, critical volume ofhydrocarbon in the fluid, the desired viscosity development in theformation to be treated will be obtained much more rapidly than if anoil free liquid were injected. Maintaining the level below the abovedescribed limit ensures that the fluid may be injected easily and intothe same flow channels of the formation as would be invaded by water.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1a illustrates a subterranean oil formation containing three strataor zones of different permeabilities, illustrating the interface betweenan injected fluid and the petroleum in each zone at a time near theeconomic end of a water flood process.

FIG. 1b illustrates the same subterranean formation, after it has beensubject to the treatment of the process of this invention, and thensubjected to additional water flood.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

Briefly, the process of our invention comprises a method of treating asubterranean petroleum-containing formation made up of at least twozones or strata whose permeabilities are sufficiently different that afluid injected into a well in communication with both zones will passprimarily through the more permeable zone. Ordinarily, for example, ifthe permeability to the flow of the injected fluid in one stratum is atleast 50 percent greater than and certaining if it is 100 percentgreater than the other stratum, fluid injected into wells in fluidcommunication with both strata will pass almost exclusively into themore permeable stratum. For example, in a water flood applied to such aformation, water will pass into the more permeable stratum exclusivelyor at least predominantly, and will displace petroleum toward theproduction well, with substantially no oil displacement occuring in theless permeable stratum. After oil has been displaced through the morepermeable stratum and oil recovery has proceeded to the point at whichwater breakthrough has occurred at the production well, continuedinjection of water into the well in communication with both strata willaccomplish substantially no additional oil recovery since all of thewater injected into the formation passes through the high permeabilitystratum, even though the oil saturation in the lesser permeable stratummay be substantially the same as it was before commencing water flood orother supplemental oil recovery operations.

Attempts to treat a situation such as that described above by techniquestaught in the prior art have been only partially successful at best fora variety of reasons. Injecting a viscous fluid, which may be either aviscous emulsion formed on the surface for the purpose of plugging themore permeable zone, or an aqueous solution of a hydrophilic polymersuch as polyacrylamide, partially hydrolyzed polyacrylamide, copolymersof acrylamide and acrylates, polysaccharides, etc., are generally notentirely satisfactory because the more viscous fluid only invades thelargest flow channels of the formation, and so does not invade all ofthe flow channels which would be invaded by a fluid whose viscosity wasmore nearly equal to the viscosity of water. Furthermore, emulsionsformed according to prior art teachings by, for example, adding causticand water to crude oil are not particularly stable with respect of timeand are also not stable with respect to changes in the salinity of fluidwith which they may be brought into contact. Thus a viscous emulsionwhich effectively plugs the larger flow channels of a high permeabilityzone, including one which has previously been water flooded, may bebroken later either as a consequence of the passage of time, or as theemulsion contacts pockets of water having greater or lesser salinity,which frequently are found in most subterranean reservoirs. Moreover,there are problems associated with adsorption of hydrophilic polymers,and furthermore many of the hydrophilic polymers are not sufficientlytemperature stable to allow them to be used in even moderate temperatureformations.

The fluid injected into the formation according to the process of ourinvention is either an aqueous oil-free solution or a low viscosity,minimum oil-containing emulsion containing two or more surfactants, orsurface-active agents, which are carefully chosen on the basis ofdisplaying optimum emulsification characteristics. Surfactants which areeffective for this purpose, e.g. for forming gross macroemulsionscapable of plugging the flow channels of the formation, are not suitablefor use in recovering oil by low surface tension flooding operations,and will not produce optimum oil displacement in a formation if utilizedin a surfactant water flooding process. The reason the surfactantssuitable for use in the process of this invention are ineffective forwater flooding operations is believed to be be that when a stableemulsion such as is employed in our process, is formed, essentially allof the surface active agents which participate in the emulsificationreaction, are concentrated at the interface between the discontinuousand continuous emulsion phases, and so little surfactants remain in theaqueous solution, and so cannot reduce the interfacial tension betweenformation petroleum and the aqueous fluid present in the flow channelsas is necessary to achieve efficient low surface tension displacement ofpetroleum.

It is necessary that the surfactants utilized in the process of thisinvention be stable and effective for emulsification at the formationtemperature in an aqueous fluid having a salinity about equal to theaverage salinity of the aqueous fluid present in the flow channel of thehigh permeability zone, e.g. the zone into which the treating fluid isto be injected. Preferably, the surfactants should be identified bytests utilizing actual fluids from the formation, including brine andformation petroleum, since particular characteristics of any of thesefluids will affect the efficiency of these surfactants foremulsification of formation petroleum.

The aqueous emulsifying treating fluid injected into the highpermeability zone in practicing the process of our invention containsthe following surfactants. (1) An organic sulfonate such as a watersoluble salt, preferably a sodium, potassium or ammonium sulfonatehaving a median equivalent weight from 325 to 475, or a water solublesalt, preferably a water soluble sodium, potassium or ammonium salt ofan alkyl sulfonate containing from 8 to 22 and preferably 10 to 18carbon atoms, or alkylaryl sulfonate having from 8 to 15 and preferablyfrom 9 to 13 carbon atoms in the alkyl chain, and (2) a water solublesalt of an alkyl or alkylarylpolyalkoxyalkylene sulfonate having thefollowing formula:

    R(OR').sub.x R"SO.sub.3 X

wherein R is an alkyl, linear or branched and having from 8 to 22 andpreferably from 10 to 18 carbon atoms, or an alkylaryl such as benzene,toluene or xylene having attached thereto an alkyl, linear or branched,containing from 8 to 15 and preferably from 9 to 13 carbon atoms in thealkyl chain, R' is ethylene or a mixture of ethylene and propylene withrelatively more ethylene than propylene, preferably at least 65%ethylene, R" is ethylene, propylene, hydroxy propylene or butylene, x isa number from 2 to 20 and preferably from 4 to 12, and X is a monovalentcation, preferably sodium, potassium or ammonium.

The equivalent weight of the organic sulfonate, the balance between Rand x in the above formula and the weight ratio of solubilizingco-surfactant are all chosen based on experimentation using petroleumand brine from the formation into which the fluid will be injected, onthe basis of exhibiting the best combination of the following:

(1) Optimum emulsifying property;

(2) Maximum emulsion viscosity;

(3) Emulsion brine tolerance;

(4) Maximum stability or emulsion at formation temperature and salinity;

(5) Tolerance for changes in aqueous fluid salinity within the range ofvariations expected in the formation and which may be caused bysubsequently injecting fluids having greater or less salinity than thesalinity of the aqueous phase of the emulsion.

A low molecular weight alcohol, e.g. a C₂ to C₇ alkanol or analkyl-substituted phenol having from 1 to 5 carbon atoms in the alkylchain, may be required or advantageous for use in the emulsifying fluid,to enhance the emulsification-forming properties or to enhance thestability of the emulsion.

In one preferred embodiment of our process, the emulsifying fluidinjected into the formation is a substantially oil-free aqueoussolution, and the residual oil present in the formation is usedexclusively to form the emulsion.

In a slightly different preferred embodiment of the process of ourinvention, a small amount of hydrocarbon is added to the emulsifyingliquid. The hydrocarbon may be crude oil, as well as kerosene, naphtha,gasoline or other commercially available mixtures, as well as C₆ to C₂₄hydrocarbons, preferably saturated hydrocarbons. The amount ofhydrocarbon which is incorporated in the emulsion is determinedexperimentally from the aqueous emulsifying fluid by preparing samplescontaining various concentrations of hydrocarbon over the range of 0.05to about 15.0 and preferably 0.5 to 5.0 percent by volume, anddetermining the viscosity of each sample. The maximum amount ofhydrocarbon which can be incorporated in the fluid without causing theviscosity of the fluid to exceed the viscosity of water or brine atformation conditions by more than 500% and preferably by no more than200%, is selected. By incorporating this small, critical volume ofhydrocarbon in the fluid, the desired viscosity development in theformation to be treated will be obtained much more rapidly than if anoil free liquid were injected. Maintaining the level below the abovedescribed limit ensures that the fluid may be injected easily and intothe same flow channels as water.

The balance between the oil soluble and water soluble groups, e.g. thenumber of carbon atoms in R and the value of n, the number of ethoxygroups, in the above formula, is slightly different for an optimumemulsifying surfactant for use in our process, compared to an optimumsurfactant for use in a low surface tension surfactant floodingprocesses.

Although it is preferred that the concentration of all of thesurfactants be determined experimentally as stated above, the followinggeneral guideline will be helpful for establishing the ranges forinitial experimentation.

The concentration of the alkyl or alkylaryl sulfonate or petroleumsulfonate surfactant will ordinarily be in the range of from about 0.01to about 10 and preferable from about 0.5 to about 4.0 percent byweight. The concentration of the alkyl or alkylarylpolyalkoxyalkylenesulfonate surfactant, will ordinarily be from about 0.1 to about 5.0 andpreferably from about 0.4 to about 2.0 percent by weight. The ratio oforganic sulfonate surfactant to the alkyl or alkylarylpolyalkoxyalkylenesulfonate will ordinarily be from about 0.5 to about 5.0, depending onthe salinity of the fluid in which it is formulated, which in turn isusually about equal to the salinity of the fluid present in thesubterranean formation.

The volume of treating fluid to be injected into the formation whenapplying the process of our invention is ordinarily from about 1.0 toabout 100 and preferably from 10 to 50 pore volume percent, based on thepore volume of the high permeability zone or zones to be contacted bythe treating fluid. It is important to note that the pore volume onwhich these numbers are based relate to the pore volume of the highpermeability zone to be treated, not the pore volume of the wholeformation.

A near well bore treatment may be effective in oil reservoirs havingimpermeable layers separating the oil zones such as shale layers. Insuch reservoirs, the volume of treating fluid is ordinarily from 50 to100 pore volume percent within the zone radius to be treated.

This fluid and process is suitable for use in formations which containwater whose salinity is from 10,000 to 200,000 parts per million totaldissolved solids, and whose temperature is as high as 150° F. (66° C.).

In another, slightly different embodiment of the process of ourinvention, the emulsion forming liquid is saturated or near saturatedwith a noncondensible gas at the injection pressure. Preferred gasessuitable for use in this embodiment are nitrogen, air, carbon dioxide,methane, ethane and natural gas. The amount of gas should be at leastslightly greater than the maximum amount which can be dissolved in theinjected liquid at reservoir conditions. The gas-saturated liquid isinjected at substantially higher pressure than formation pressure,preferably at the maximum injection pressure which is safely below thefracture pressure of the overburden formation. After the desired amountof liquid has been injected into the zone or layer of the formation, thepressure is reduced to a value about equal to the normal formationpressure. This causes small gas bubbles to break out of solution in theinjected emulsifying liquid and/or emulsion formed in the zone. Thebreakout of gas bubbles contributes at least two beneficial effects toour process: (1) mixing energy is made available to assist in theforming of the emulsion, and in forming dispersed phase cells which aresmaller and thus maximizing the viscosity of the emulsion. (2) At leasta portion of the gas bubbles are trapped in the viscous emulsion in thezone, forming a stable foam which increases both the viscosity and thevolume of the emulsion formed in the pore spaces, thus enhancing theeffectiveness of the permeability reduction obtained from application ofour process.

The procedural steps involved in applying the process of our inventionto a subterranean formation are best understood by referring to theattached drawing, to which the following description of a field exampleapplies.

A subterranean, petroleum-containing formation is located at depth ofabout 6200 feet, and it is determined that the total thickness of theformation is 35 feet. The formation is not homogeneous in terms ofpermeability, however; rather, the formation is made up of threeseparate strata or layers. The oil saturation in all three layers isapproximately 30 percent. Layer 1, the top layer in the formation, has apermeability of about 6 md and is approximately 10 feet thick. Layer 2,the middle zone of the formation, has a permeability of about 46 md andis about 15 feet thick. Layer 3, which occupies the lower portion of theformation, is approximately 10 feet thick and has an averagepermeability of about 15 md. The formation temperature is 105° F. (40.6°C.).

Water is injected into injection well 5 which is in fluid communicationwith the full vertical thickness of the formation, i.e., with all threelayers of the formation. Since the permeability of layer 2 issubstantially greater than the permeability of either layer 1 or layer3, water flows much more readily into layer 2, and substantially all ofthe oil production obtained as a consequence of water injection is infact derived from layer 2. It should be noted that this is notnecessarily apparent to operators on the surface of the earth, however.Water injection continues and an interface is formed in each layerbetween the injected water flood and an oil bank that is formed as aconsequence of the water flood, which are designated as 6 in layer 1, 7in layer 2 and 8 in layer 3. At a time just before water breakthrough atthe production well 4, the position of interfacial zones 6, 7 and 8 isshown in FIG. 1A. It can be seen that water breakthrough is about tooccur at production well 4 from layer 2. After water breakthrough hasoccurred, further injection of water into well 5 will not recover anysignificant amount of additional oil from any of the three layers. Allof the water injected after breakthrough of water at production well 4will pass into and through layer 2, and essentially no additional waterwill pass into layers 1 and 3. Thus interfaces 6 and 8 will remainapproximately where they are shown in FIG 1a after breakthrough of waterinto the production well at layer 2, no matter how much additional wateris injected into the injection well and flowed through the reservoir. Atthis time oil production drops off rapidly and the amount of water beingproduced increases rapidly until further water injection and oilproduction are no longer economically feasible, even though largeamounts of oil remain in layers 1 and 3.

The water that has been utilized for water flooding is itself from thesame formation, and so the salinity of the water being injected into theformation and the salinity of water naturally present in the formationis about the same, and it is determined that in this example thesalinity of this water is approximately 180,000 parts per million totaldissolved solids including 9800 parts per million divalent ions,principally calcium and magnesium. It is desired to formulate a treatingfluid suitable for use in this high salinity environment, and thesurfactant is chosen by a series of laboratory experiments employingactual samples of field water and petroleum from the formation intowhich the treating fluid is to be injected. After a series of laboratorytests, essentially similar to those to be described later hereinafterbelow, it is determined that a preferred emulsifying fluid for use inreducing the permeability of layer 2 contains (1) 1.5 percent by weightof an ammonium petroleum sulfonate having a median equivalent weight of380 and (2) 0.8 percent by weight of a sodiumdodecylbenzenepolyethoxyethylene sulfonate containing an average of 3.5ethoxy groups per molecule, plus 2.0 percent by weight of iso-pentanol.

Since the wells are 150 feet apart, and the formation to be treated isprincipally layer 2, which is 15 feet thick, and since it is determinedthat the swept area in a simple two-spot pattern such as this is 11,200square feet, the volume of formation (30% porosity) to be treated is(11,200)(15)(0.30) =50,400 cu. ft.

A 20 percent pore volume slug is chosen for use in treating the aboveidentified zone. Accordingly, the volume of the solution necessary totreat layer 2 in this example is approximately 10,080 cubic feet (2133cubic meters) or 75,398 gallons.

The above described emulsifying fluid is injected into injection well 5.Because the permeability of layer 2 is substantially greater than thepermeability of layers 1 and 3 at that time, the difference beingsubstantially greater than it was existed at the time water flooding wasinitiated, it is not necessary to isolate layer 2 from the other layersfor the purpose of selectively injecting the fluid into layer 2.Substantially all of the fluid injected into well 5, which is in fluidcommunication with all of the formation, will pass into layer 2.Injection of the treating fluid into layer 2, which causes an emulsionto form in layer 2, reducing the permeability of the layer andadditionally recovering some additional oil therefrom, reduces the oilsaturation in layer 2 to only 4 percent.

After injecting 10 pore volume percent of the emulsifying liquid intothe formation, 1.5 percent by volume of crude oil is added to theformation, which only increases the viscosity of the fluid by 75% overthe viscosity of the liquid without the oil, but increases the rate offormation of the emulsion in situ in the flow channels. Water injectionis then again resumed into the formation. Since the permeability oflayer 2 has been decreased substantially, water injected into well 5will now flow principally into layers 1 and 3, and so will continuepushing the interface between the injected water and the formationpetroleum toward the production well. If water from layer 3 breaksthrough at producing well 4 before it does in layer 1, it may benecessary to treat layer 3 in about the same fashion as was used totreat layer 2 in the procedural steps described above. After this hasbeen accomplished, water injection may again be resumed, withessentially all of the water passing into layer 1. Water injection isthen continued until water again breaks through at well 4, signifyingthat substantially all of the formation has been swept by waterflooding.

After completion of the above described multi-step water flood withintermittent treatment to alleviate the adverse permeabilitydistribution problem, the formation may thereafter be subjected toadditional supplemental oil recovery processes such as, for example,surfactant flooding, since the permeability of the formation has nowbeen made more homogeneous and there still remains a substantial amountof petroleum in layers 1 and 3 sufficient to justify the injection of anefficient, low surface tension oil displacing fluid into layers 1 and 3.

For the purpose of illustrating the types of fluids suitable for use inthe process of our invention, and illustrating the results obtainablefrom application thereof, a series of laboratory experiments wereperformed.

A series of emulsification tests were conducted to illustrate how slightchanges in surfactant molecular characteristics affect emulsificationeffectiveness of the surfactant. These tests comprised mixing together 5cc's of oil and 30 cc's of the one percent surfactant solution in an 85kilogram/meter³ (85,000 ppm) brine. The solutions were heated to atemperature of 109° F. (42.8° C.) and shaken periodically over an eighthour period. The solutions were then allowed to equilibrate for severaldays, and the volume of emulsion and total volume of fluid including theemulsion, the oil and the aqueous phase, were observed. The figuresreported in Table I below under volume ratio represents the volume ofemulsion divided by the total volume of fluid, including emulsion andseparate phases of the field brine and any unemulsified oil that mayhave been present. It can be seen that a change in the number of ethoxygroups of only ±0.2 causes a very significant change in theemulsification effectiveness of the surfactant.

                  TABLE I                                                         ______________________________________                                              Average number of moles                                                                          Emulsification ratio                                       of ethylene oxide per                                                                            (volume of emulsion                                  Run   mole of surfactant.sup.1                                                                         ÷ total fluid volume)                            ______________________________________                                        1     2.6                0.02                                                 2     2.8                0.39                                                 3     3.0                0.02                                                 4     3.2                0.00                                                 5     3.4                0.00                                                 ______________________________________                                         .sup.1 One percent of sodium dodecylbenzenepolyethoxyhydroxypropylene         sulfonate.                                                               

Laboratory equipment was especially constructed for core flood tests,and comprised essentially two separate formation earth core samples ofsignificantly different permeabilities encased in holders and arrangedfor flooding, with the two cores being placed in parallel to simulatethe situation similar to that described above, in which an injectionwell contacts two earth strata of substantially differentpermeabilities. Fluids injected into the apparatus will passpredominantly through the highest permeability core to the exclusion ofthe other core. In all of the experiments described below, the coreswere separately water flooded to an irreducable oil saturation prior tobeing connected in parallel for the purpose of studying the effect ofthe adverse permeability distribution-correcting treatment of ourinvention.

In the first experiment of this series, run 7, core A was a fresh Bereasandstone core having a permeability of 704 millidarcy. The core was5.08 cm in diameter and 15.8 cm in length and had a total pore volume of73 cubic centimeters. The porosity was 23 percent. The residual oilsaturation after water flooding was 25 percent. Core B utilized in Run 7was a similar size core having pore volume of 65 cubic centimeters and aporosity of 20 percent, but a much lower permeability, only 139millidarcy. The residual oil saturation of Core B after water floodingwas 35 percent. After the cores were flooded to irreducable watersaturation and mounted in parallel, water injection into the cores at aflow rate of 0.9 cc per minute resulted in a receptivity ratio (theratio of the volume of fluid injected into core A divided by the volumeof fluid injected into core B during the same period, when the cores areconnected in parallel) of approximately 5.8. During the treatmentprocedure the receptivity ratio declined to 4.7 and levelled off at 4.0during the subsequently applied water flood operation. A quantity ofpetroleum sulfonate solution was then injected, and during thesurfactant flood portion of the test, the receptivity declined stillfurther to 2.4. A polymer mobility control buffer was then injected intothe system, and the receptivity ratio increased to 4.2 after 0.2 porevolumes of the polymer solution had been injected, and then rose to 5.6after 1 pore volume of polymer had been injected. It is believed thatthe increase in receptivity ratio resulting from the fact that thepolymer was dissolved in fresh water, which broke the emulsion formed inthe course of the treatment procedure described above. Nevertheless, Run7 clearly illustrates how treatment of two cores in a parallelarrangement, which cores have widely different permeabilities, canreduce the permeability deviation between the two cores and improve thereceptivity ratio from 5.8 to 2.4, which is substantially less than halfof the original receptivity ratio.

Run 8 was performed to verify that in situ emulsification was themechanism responsible for the improvement in receptivity noted inexperiment 7 above. In Run 8, two packs of crushed formation corematerial were formulated and cleaned. Pack C was saturated with crudeoil and pack D was not. Pack C was water flooded to an irreducable oilsaturation prior to the treatment. Both packs were treated with 13 porevolume percent of a 30 kilogram/meter³ solution ofdinonylphenolpolyethoxyethyl sulfonate (3.8 ethoxy groups per moleculeaverage) and finally flooded with field brine. In this experiment, thepacks were not flooded in parallel as was the case in Run 7 above butrather were independently flooded after treatment with the emulsifyingfluid. The pressure differential across the packs was determined duringthe course of the treatment and subsequent water flood as an indicationof increasing resistance to fluid flow through the packs. The pack whichwas originally saturated with oil, water flooded and then treated,experienced a four-fold increase in the pressure required to flood withwater in a constant rate flood whereas the pack which containedessentially no oil prior to the treatment experienced less than a 50percent increase in differential pressure during the course ofapproximately 3 pore volumes of water flood. This clearly illustratesthat oil must be present in the treated formation for theinjectivity-reducing emulsification phenomena to be achieved, which isnecessary for the treatment described herein to accomplish the desiredobjective of reducing the permeability of the high permeability zone.

Experiment 9 was comparable to experiment 7, except the treatingsolution contained 13.6 kg/m³ dodecylbenzene (3.0) polyethoxyethylenesulfonate with 7.6 kg/m³ 3.0 mole ethylene oxide adduct of dodecylphenoland packs were formulated from crushed formation core material. Pack Ehad 96 millidarcy permeability and Pack F had 20 millidarcypermeability. After the packs were each flooded to irreducable watersaturation and mounted in parallel, water injection into the cores at aflow rate of 1.0 cm³ per minute in a receptivity ratio (Pack E/Pack F)of 4.6. During the treatment procedure, the receptivity ratio decline to2.8 and levelled off at 1.0 during the subsequently applied water floodoperation. A receptivity ratio of 1 was maintained during injection ofpetroleum sulfonate solution and the ratio fluctuated between 1.6 and0.6 during a polymer solution injection. Experiment 9 clearlyillustrates that the sulfonate-nonionic mixture can be used to reducethe permeability deviation between two packs.

                                      TABLE II                                    __________________________________________________________________________                                   Receptivity                                                                          Ratios                                     Core or                                                                            Initial Permeability                                                                    Volume of                                                                             Material                                                                           Prior  After ΔP After Treatment          Run                                                                              Pack to Water  Treating Fluid                                                                        Used To Treatment                                                                         Treatment                                                                           ΔP Before                   __________________________________________________________________________                                                Treatment                            A    704       .14                                                         7                         (2)  5.8     4.0.sup.1                                                                          --                                   B    139       .03                                                            C    75        0.13         --     --    4.0                               8                         (2)                                                    D    65        0.17         --     --    1.4                                  E    96                                                                    9                         (3)  4.6    1.0   --                                   F    20                                                                    __________________________________________________________________________     .sup.1 Reduced to 2.4 on injecting petroleum sulfonate oil displacing         fluid                                                                         .sup.2 Dinonylphenol (3.8) polyethoxyethyl sulfonate                          .sup.3 Dodecylphenol (3.0) polyethoxyethyl sulfonate + dodecylphenol (3.0     polyethoxylate                                                           

While the above discloses mixing the two essential surfactants in asingle fluid, two or more fluids each containing only one component canbe injected sequentially so as to achieve mixing in the formation. Incertain applications, there is an advantage to this embodiment in thatemulsification is delayed and greater in depth treatment of the highpermeability zone is achieved.

Thus we have disclosed and demonstrated how it is possible to treat aformation containing two or more strata of substantially differentpermeabilities so as to reduce the permeability of the more permeablestrata, by injecting an emulsifying fluid thereinto which forms a grossmacroemulsion with residual oil remaining in the flow channels of theflooded portion of a formation after water flooding, thereby reducingthe permeability difference between the strata, after which water orother oil displacing fluids may be injected into the formation withsubstantially improved vertical conformance over that which would beobtained without the permeability adjusting treatment of our invention.

While our invention has been described in terms of a number ofillustrative embodiments, it is clearly not so limited since manyvariations thereof will be apparent to persons skilled in the art of oilrecovery without departing from the true spirit and scope of ourinvention. It is our desire and intention that our invention be limitedonly by those limitations and restrictions appearing in the claimsappended immediately hereinafter below.

We claim:
 1. A method of recovering petroleum from a subterranean,petroleum-containing formation, the temperature of said formation beingfrom 80° F. to 300° F. said formation containing water whose salinity isfrom 20,000 to 250,000 parts per million total dissolved solids, saidformation containing at least two distinct petroleum-containing strataor layers, the permeability of at least one of said strata being atleast 50 percent greater than the permeability of the other stratum,said formation being penetrated by at least one injection well and by atleast one production well, both wells being in fluid communication withat least two of said formation strata, comprising(a) injecting a firstaqueous oil-displacing fluid into the formation via the injection well,said fluid passing through at least one of the more permeable strata ofsaid formation and displacing oil therein toward the production well,from which it is recovered to the surface of the earth; (b) after saidfirst aqueous oil displacing fluid has passed substantially through atleast one of said more permeable strata to the production well,discontinuing injecting said fluid and injecting into said stratum anaqueous emulsifying fluid containing an emulsifying surfactantcombination comprising (1) an organic sulfonate anionic surfactantselected from the group consisting of water soluble sodium, potassium orammonium salts of alkyl sulfonates having from 9 to 25 carbon atoms,alkylaryl sulfonates having from 8 to 15 carbon atoms in the alkylchain, or petroleum sulfonate whose median equivalent weight is from 325to 475, (2) an aliphatic polyalkoxyalkylene sulfonate oralkylarylpolyalkoxyalkylene sulfonate having the following formula:

    RO(R'O).sub.n R"SO.sub.3 M

wherein R is an aliphatic, preferably an alkyl, linear or branched,having from 9 to 25 carbon atoms, or an alkylaryl group selected fromthe group consisting of benzene, toluene, and xylene having attachedthereto at least one alkyl group, linear or branched, having from 8 to15 carbon atoms; R' is ethylene or a mixture of ethylene and highermolecular weight alkylene with relatively more ethylene than highermolecular weight alkylene; n is a number including fractional numbers,from 2 to 10; R" is ethylene, propylene, hydroxy propylene or butylene,and M is a monovalent cation selected from the group consisting ofsodium, potassium, lithium and ammonium; (c) thereafter injecting asecond oil displacing fluid into the formation and recovering petroleumdisplaced by the fluid from the formation via the producing well.
 2. Amethod as recited in claim 1 wherein the first oil displacing fluid iswater.
 3. A method as recited in claim 1 wherein the second oildisplacing fluid is water.
 4. A method as recited in claim 1 wherein Ris an alkyl group containing from 10 to 18 carbon atoms.
 5. A method asrecited in claim 1 wherein R is an alkylaryl group and the number ofcarbon atoms in the alkyl group is from 9 to
 13. 6. A method as recitedin claim 5 wherein R is an alkylbenzene group containing from 9 to 13carbon atoms in the alkyl chain.
 7. A method as recited in claim 1wherein R' is ethylene.
 8. A method as recited in claim 1 wherein R' ispropylene.
 9. A method as recited in claim 1 wherein R' is hydroxypropylene.
 10. A method as recited in claim 1 wherein R' is butylene.11. A method as recited in claim 1 wherein the value of n is from 2 to7.
 12. A method as recited in claim 1 wherein the ratio of the organicsulfonate surfactant to the aliphaticpolyalkoxyalkylene sulfonate oralkylarylpolyalkoxyalkylene sulfonate is from about 0.1 to about 1.0.13. A method as recited in claim 1 wherein the concentration of thealiphatic polyalkoxyalkylene sulfonate or alkylarylpolyalkoxyalkylenesulfonate is from about 0.01 to about 10.0 percent by weight.
 14. Amethod as recited in claim 13 wherein the concentration of the aliphaticpolyalkoxyaline sulfonate or alkylarylpolyalkoxyalklane sulfonatesurfactant is from about 0.5 to about 4.0 percent by weight.
 15. Amethod as recited in claim 1 wherein the concentration of organicsulfonate surfactant is from about 0.10 to about 10.0 percent by weight.16. A method as recited in claim 15 wherein the concentration of organicsulfonate surfactant is from about 0.5 to about 4.0 percent by weight.17. A method as recited in claim 1 wherein the volume of emulsifyingsurfactant-containing fluid is from about 1.0 to about 100 pore volumepercent based on the pore volume of the strata to be treated thereby.18. A method as recited in claim 1 wherein the volume of fluid is fromabout 10 to about 50 pore volume percent.
 19. A method as recited inclaim 1 wherein said formation contains at least three strata, eachdiffering in permeability from one another, and the steps of injectingsaid emulsifying surfactant-containing fluid and then resuming injectingsaid aqueous oil-displacing fluid are applied to the formation at leasttwice.
 20. A method as recited in claim 11 wherein the steps ofinjecting said emulsifying surfactant-containing fluid and said aqueousoil-displacing fluid are repeated until oil-displacing fluid has sweptsubstantially all of the petroleum-containing strata of said formation.21. A method as recited in claim 1 wherein the emulsifying liquid alsocontains from 0.1 to 10 percent by weight of a C₂ to C₇ alcohol.
 22. Amethod as recited in claim 1 wherein the emulsifying liquid alsocontains an amount of hydrocarbon sufficient to increase the viscosityof the emulsifying to a value which is from 200 to 500 percent greaterthan the viscosity of formation water.
 23. A method as recited in claim22 wherein the hydrocarbon is selected from the group consisting ofcrude oil, diesel oil, kerosene, gasoline, naphtha, C₆ to C₂₄ parafins,and mixtures thereof.
 24. A method as recited in claim 1 comprising theadditional steps of(1) saturating the emulsifying fluid with anoncondensible gas at the injection temperature and pressure which isgreater than normal formation pressure and below fracture pressure priorto injecting it into the formation; and (2) reducing the pressure in thetreated zone to cause gas to break out of solution in the fluid in theformation.
 25. A method as recited in claim 24 wherein the gas isselected from the group consisting of air, nitrogen, carbon dioxide,methane, ethane, natural gas, and mixtures thereof.
 26. A method asrecited in claim 1 comprising injecting a first fluid containing thealiphatic polyalkoxyalkylene sulfonate or alkylarylpolyalkoxyalkylenesulfonate followed by injecting a second quantity of fluid containingthe organic sulfonate surfactant, so the surfactants mix in theformation.
 27. A method as recited in claim 1 comprising injecting afirst fluid containing the organic sulfonate surfactant followed byinjecting a second slug of fluid containing the aliphaticpolyalkoxyalkylene sulfonate or alkylarylpolyalkoxyalkylene sulfonate sothe surfactants mix in the formation.